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UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D. C.
20549

FORM 10-Q

|x                             |  | QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
|----------------------------- |  | ----------------------------------------------------------------------------------
|                              |  |                                                                                   
|                              |  | For the quarterly period ended June 30, 2003                                      
|                              |  |                                                                                   
|                              |  | OR                                                                                
|                              |  |                                                                                   
|o                             |  | TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|                              |  |                                                                                   
|                              |  | For the transition period from ______________ to ______________                   
|                              |  |                                                                                   
|Commission File Number 1-7796

TIPPERARY CORPORATION (Exact name of registrant as specified in its charter)

|Texas                                                          |  | 75-1236955                          
|-------------------------------------------------------------- |  | ------------------------------------
|(State or other jurisdiction of incorporation or organization) |  | (I.R.S. Employer Identification No.)
|                                                               |  |                                     
|633 Seventeenth Street, Suite 1550 Denver, Colorado            |  | 80202                               
|(Address of principal executive offices)                       |  | (Zip Code)                          
|                                                               |  |                                     
|(303) 293-9379                                                
|(Issuers telephone number)                                   

Check whether the issuer (1) filed all
reports required to be filed by Section 13 or 15(d) of the Exchange Act of 1934 during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for
the past 90 days.

|Yes x | No o
|----- | ----

Indicate by check mark whether the registrant is
an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

|Yes o | No x
|----- | ----

State the number of shares outstanding of each
of the issuers classes of common stock, as of the latest practicable date.

|Class                        |  | Outstanding at August 14, 2003
|---------------------------- |  | ------------------------------
|                             |  |                               
|Common Stock, $.02 par value |  | 39,221,489 shares             

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TIPPERARY CORPORATION AND SUBSIDIARIES

Index to Form 10-Q

|              | Page No.                         
|------------- | ---------------------------------
|              |                                  
|PART I.       | FINANCIAL INFORMATION (UNAUDITED)
|              |                                  
|              | Item 1.                          
|              |                                  
|              |                                  
|              |                                  
|              |                                  
|              |                                  
|              |                                  
|              |                                  
|              |                                  
|              |                                  
|              | Item 2.                          
|              |                                  
|              | Item 4.                          
|              |                                  
|PART II.      | OTHER INFORMATION                
|              |                                  
|              | Item 1.                          
|              |                                  
|              | Item 6.                          
|              |                                  
|SIGNATURES    | 23                               
|              |                                  
|EXHIBIT INDEX | 24                               
|              |                                  



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PART I - FINANCIAL INFORMATION

Item 1.  Financial Statements

TIPPERARY CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets (in thousands) (unaudited)

|                                                                                                                       |  | June 30 2003 |          | December 31 2002 |  
|---------------------------------------------------------------------------------------------------------------------- |  | ------------ | -------- | ---------------- | -
|                                                                                                                       |  |              |          |                  |  
|ASSETS                                                                                                                 |  |              |          |                  |  
|Current assets:                                                                                                        |  |              |          |                  |  
|Cash and cash equivalents                                                                                              |  | $            | 1,946    |                  | $
|Restricted cash                                                                                                        |  |              | 152      |                  |  
|Receivables                                                                                                            |  |              | 2,665    |                  |  
|Other current assets                                                                                                   |  |              | 134      |                  |  
|                                                                                                                       |  |              |          |                  |  
|Total current assets                                                                                                   |  |              | 4,897    |                  |  
|                                                                                                                       |  |              |          |                  |  
|Property, plant and equipment, at cost:                                                                                |  |              |          |                  |  
|Oil and gas properties, full cost method                                                                               |  |              | 92,572   |                  |  
|Other property and equipment                                                                                           |  |              | 4,350    |                  |  
|                                                                                                                       |  |              |          |                  |  
|                                                                                                                       |  |              | 96,922   |                  |  
|Less accumulated depreciation, depletion and amortization                                                              |  |              | (6,456   | )                |  
|                                                                                                                       |  |              |          |                  |  
|Property, plant and equipment, net                                                                                     |  |              | 90,466   |                  |  
|                                                                                                                       |  |              |          |                  |  
|Deferred loan costs                                                                                                    |  |              | 5,156    |                  |  
|Other noncurrent assets                                                                                                |  |              | 256      |                  |  
|                                                                                                                       |  |              |          |                  |  
|                                                                                                                       |  | $            | 100,775  |                  | $
|                                                                                                                       |  |              |          |                  |  
|LIABILITIES AND STOCKHOLDERS EQUITY                                                                                   |  |              |          |                  |  
|Current liabilities:                                                                                                   |  |              |          |                  |  
|Current portion of long-term debt                                                                                      |  |              | 4,000    |                  |  
|Accounts payable                                                                                                       |  |              | 2,635    |                  |  
|Accrued liabilities                                                                                                    |  |              | 1,674    |                  |  
|Royalties payable                                                                                                      |  |              | 144      |                  |  
|                                                                                                                       |  |              |          |                  |  
|Total current liabilities                                                                                              |  |              | 8,453    |                  |  
|                                                                                                                       |  |              |          |                  |  
|Long-term debt                                                                                                         |  |              | 39,091   |                  |  
|Long-term asset retirement obligation                                                                                  |  |              | 202      |                  |  
|Minority interest                                                                                                      |  |              | 785      |                  |  
|Commitments and contingencies (Note 5)                                                                                 |  |              |          |                  |  
|Stockholders equity                                                                                                   |  |              |          |                  |  
|Preferred stock:                                                                                                       |  |              |          |                  |  
|Cumulative; par value $1.00; 10,000,000 shares authorized; none issued                                                 |  |              |         |                  |  
|Non-cumulative, par value $1.00; 10,000,000 shares authorized; none issued                                             |  |              |         |                  |  
|Common stock; par value $.02; 50,000,000 shares authorized; 39,231,087 shares issued and 39,221,489 shares outstanding |  |              | 785      |                  |  
|Capital in excess of par value                                                                                         |  |              | 149,967  |                  |  
|Accumulated deficit                                                                                                    |  |              | (102,287 | )                |  
|Accumulated other comprehensive income                                                                                 |  |              | 3,804    |                  |  
|Treasury stock, at cost; 9,598 shares                                                                                  |  |              | (25      | )                |  
|                                                                                                                       |  |              |          |                  |  
|Total stockholders equity                                                                                             |  |              | 52,244   |                  |  
|                                                                                                                       |  |              |          |                  |  
|                                                                                                                       |  | $            | 100,775  |                  | $
|                                                                                                                       |  |              |          |                  |  

See accompanying notes to consolidated financial statements.

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TIPPERARY CORPORATION AND SUBSIDIARIES
Consolidated Statements of Operations (in thousands, except per share data) (unaudited)

|                                                                         |  | Three months ended June 30 |        | Six months ended June 30 |  
|------------------------------------------------------------------------ |  | -------------------------- | ------ | ------------------------ | -
|                                                                         |  |                            |        |                          |  
|                                                                         |  | 2003                       |        | 2002                     |  
|                                                                         |  |                            |        |                          |  
|Revenues                                                                 |  | $                          | 1,709  |                          | $
|                                                                         |  |                            |        |                          |  
|Costs and expenses:                                                      |  |                            |        |                          |  
|Operating                                                                |  |                            | 1,111  |                          |  
|Depreciation, depletion and amortization                                 |  |                            | 398    |                          |  
|Gain on sale of assets                                                   |  |                            |       |                          |  
|Write-down of oil and gas properties                                     |  |                            | 2,221  |                          |  
|Asset retirement obligation accretion                                    |  |                            | 6      |                          |  
|General and administrative                                               |  |                            | 1,291  |                          |  
|                                                                         |  |                            |        |                          |  
|Total costs and expenses                                                 |  |                            | 5,027  |                          |  
|                                                                         |  |                            |        |                          |  
|Operating loss                                                           |  |                            | (3,318 | )                        |  
|Other income (expense):                                                  |  |                            |        |                          |  
|Other income                                                             |  |                            |       |                          |  
|Interest income                                                          |  |                            | 15     |                          |  
|Interest expense                                                         |  |                            | (1,175 | )                        |  
|Foreign currency exchange gain                                           |  |                            | 3,117  |                          |  
|                                                                         |  |                            |        |                          |  
|Total other (expense) income                                             |  |                            | 1,957  |                          |  
|                                                                         |  |                            |        |                          |  
|Loss before income taxes                                                 |  |                            | (1,361 | )                        |  
|Income tax benefit                                                       |  |                            |       |                          |  
|                                                                         |  |                            |        |                          |  
|Loss before minority interest and cumulative effect of accounting change |  |                            | (1,361 | )                        |  
|Minority interest in (income) loss of subsidiary                         |  |                            | (265   | )                        |  
|                                                                         |  |                            |        |                          |  
|Loss before cumulative effect of accounting change                       |  |                            | (1,626 | )                        |  
|Cumulative effect of accounting change                                   |  |                            |       |                          |  
|                                                                         |  |                            |        |                          |  
|Net loss                                                                 |  | $                          | (1,626 | )                        | $
|                                                                         |  |                            |        |                          |  
|Net loss per share                                                       |  |                            |        |                          |  
|Basic and diluted                                                        |  |                            | (.04   | )                        |  
|                                                                         |  |                            |        |                          |  
|Weighted average shares outstanding                                      |  |                            |        |                          |  
|Basic and diluted                                                        |  |                            | 39,221 |                          |  
|                                                                         |  |                            |        |                          |  

See accompanying notes to consolidated financial statements.

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TIPPERARY CORPORATION AND SUBSIDIARIES
Consolidated Statements of Cash Flows (in thousands) (unaudited)

|                                                                            |  | Six months ended June 30 |        
|--------------------------------------------------------------------------- |  | ------------------------ | -------
|                                                                            |  |                          |        
|                                                                            |  | 2003                     |        
|                                                                            |  |                          |        
|Cash flows from operating activities:                                       |  |                          |        
|Net loss                                                                    |  | $                        | (4,341 
|Adjustments to reconcile net loss to net cash used in operating activities: |  |                          |        
|Depreciation, depletion and amortization                                    |  |                          | 706    
|Amortization of deferred loan costs                                         |  |                          | 708    
|Compensatory warrants granted                                               |  |                          | 4      
|Minority interest in income (loss) of subsidiary                            |  |                          | 181    
|Foreign currency exchange gain                                              |  |                          | (3,113 
|Gain on sale of assets                                                      |  |                          |       
|Asset retirement obligation accretion                                       |  |                          | 12     
|Cumulative effect of accounting change                                      |  |                          | 46     
|Write-down of oil and gas properties                                        |  |                          | 2,221  
|Changes in current assets and current liabilities:                          |  |                          |        
|Increase in receivables                                                     |  |                          | (710   
|Decrease in prepaid drilling costs and other current assets                 |  |                          | 180    
|Increase (decrease) in accounts payable and accrued liabilities             |  |                          | 1,005  
|Increase (decrease) in royalties payable                                    |  |                          | 14     
|                                                                            |  |                          |        
|Net cash used in operating activities                                       |  |                          | (3,087 
|                                                                            |  |                          |        
|Cash flows from investing activities:                                       |  |                          |        
|Proceeds from asset sales                                                   |  |                          |       
|Capital expenditures                                                        |  |                          | (11,982
|                                                                            |  |                          |        
|Net cash used in investing activities                                       |  |                          | (11,982
|                                                                            |  |                          |        
|Cash flows from financing activities:                                       |  |                          |        
|Proceeds from borrowings                                                    |  |                          | 19,705 
|Principal repayments                                                        |  |                          | (4,940 
|Decrease in restricted cash                                                 |  |                          | 394    
|Payments for deferred loan costs                                            |  |                          | (90    
|                                                                            |  |                          |        
|Net cash provided by financing activities                                   |  |                          | 15,069 
|                                                                            |  |                          |        
|Effect of exchange rate changes on cash                                     |  |                          | 221    
|Net increase (decrease) in cash and cash equivalents                        |  |                          | 221    
|Cash and cash equivalents at beginning of period                            |  |                          | 1,725  
|                                                                            |  |                          |        
|Cash and cash equivalents at end of period                                  |  | $                        | 1,946  
|                                                                            |  |                          |        
|Supplemental disclosure of cash flow information:                           |  |                          |        
|Cash paid during the period for:                                            |  |                          |        
|Interest                                                                    |  | $                        | 1,599  
|Income taxes                                                                |  | $                        |       
|Non-cash investing and financing activities:                                |  |                          |        
|Issuance of stock to acquire assets                                         |  | $                        |       

See accompanying notes to consolidated financial statements.

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TIPPERARY CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

In the opinion of management, the accompanying unaudited consolidated financial statements reflect all adjustments, consisting only of normal
recurring adjustments, which are necessary for a fair presentation of the financial position of Tipperary Corporation and its subsidiaries (the Company) at June 30, 2003, and the results of its operations for the three-month and
six-month periods ended June 30, 2003 and 2002 and its cash flows for the six-month periods ended  June 30, 2003 and 2002. The consolidated financial statements include the accounts of Tipperary Corporation and its wholly-owned subsidiaries,
Tipperary Oil and Gas Corporation and Burro Pipeline Corporation, and its 90%-owned subsidiary, Tipperary Oil and Gas (Australia) Pty Ltd (TOGA).  All intercompany balances have been eliminated.  The accounting policies
followed by the Company are included in Note 1 to the Consolidated Financial Statements in its Annual Report on Form 10-KSB for the year ended December 31, 2002.  These financial statements should be read in conjunction with the Form
10-KSB.

Impact of New Accounting Pronouncements

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial
Instruments with Characteristics of Both Liabilities and Equity (SFAS 150).  SFAS 150 establishes standards on the classification and measurement of certain financial instruments with characteristics of both liabilities and
equity.  The provisions of SFAS 150 are effective for financial instruments entered into or modified after May 31, 2003, and to all other instruments that exist as of the beginning of the first interim financial reporting period beginning after
June 15, 2003.  The Company does not believe the adoption of SFAS 150 will have a material effect on its financial statements.

In June 2001, the FASB issued SFAS No. 143, Accounting for
Asset Retirement Obligations (SFAS 143), which provides accounting requirements for retirement obligations associated with tangible long-lived assets, including the timing of liability recognition, initial measurement of the
liability, allocation of asset retirement costs to expense, subsequent measurement of the liability, and financial statement disclosures.  SFAS 143 requires that asset retirement costs be capitalized along with the cost of the related
long-lived asset.  The asset retirement costs should then be allocated to expense using a systematic and rational method.  The Company has determined that it has asset retirement costs associated with wells drilled in Australia and the
United States.  The Company also expects to incur retirement costs to dismantle two gas compression plant facilities located in Australia. The Company adopted SFAS 143 on January 1, 2003, which resulted in an increase in property, plant and
equipment of $134,000 and establishment of an asset retirement obligation of $180,000.  The transition adjustment of $46,000 was reported as a cumulative effect of accounting change.  If the Company had applied the provisions of SFAS 143
as of January 1, 2002, the Companys asset retirement obligation would have been $145,000 at January 1, 2002.  The Companys pro forma net loss would have been $942,000 and $2,530,000 for the three and six months ended June 30, 2002
assuming SFAS 143 had been adopted on January 1, 2002.  As a result of adopting SFAS 143, the estimated asset retirement obligation accretion for 2003 is expected to be approximately $23,000.

|Beginning asset retirement obligation at January 1, 2003 |  | $ | 180,000 | 
|-------------------------------------------------------- |  | - | ------- | 
|Asset retirement obligation accretion                    |  |   | 12,000  | 
|Asset retirement obligation additions                    |  |   | 10,000  | 
|                                                         |  |   |         | 
|Ending asset retirement obligation at June 30, 2003      |  | $ | 202,000 | 
|                                                         |  |   |         | 

In June 2001, the FASB issued SFAS No. 141, Business Combinations (SFAS 141) and
SFAS No. 142, Goodwill and Intangible Assets (SFAS 142).  SFAS 141 and 142 became effective on July 1, 2001 and January 1, 2002, respectively.  SFAS 141 requires all business combinations initiated after June 30,
2001 to be accounted for using the purchase method.  Additionally, SFAS 141 requires companies to disaggregate and report separately from goodwill certain

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intangible assets.  SFAS 142 establishes new guidelines for accounting for goodwill and other intangible assets.  Under SFAS 142, goodwill and certain other
intangible assets are not amortized, but rather are reviewed annually for impairment. The FASB, the Securities and Exchange Commission (SEC) and others continue to discuss the appropriate application of SFAS 141 and 142 to oil and gas mineral rights
held under lease and other contractual arrangements representing the right to extract such reserves.  Depending on the outcome of such discussions, these oil and gas mineral rights held under lease and other contractual arrangements
representing the right to extract such reserves for both undeveloped and developed leaseholds may be classified separately from oil and gas properties, as intangible assets on the Companys balance sheets.  In addition, the disclosures
required by SFAS 141 and 142 relative to intangible assets would be included in the notes to financial statements.  Historically, the Company, like many other oil and gas companies, has included these oil and gas mineral rights held under lease
and other contractual arrangements representing the right to extract such reserves as part of oil and gas properties, even after SFAS 141 and 142 became effective.

As applied to companies that
have adopted full cost accounting for oil and gas activities, the Company understands that this interpretation of SFAS 141 and 142 would only affect the Companys balance sheet classification of proved oil and gas leaseholds acquired after June
30, 2001 and the Companys unproved oil and gas leaseholds.  The Companys results of operations and cash flows would not be affected, since these oil and gas mineral rights held under lease and other contractual arrangements
representing the right to extract such reserves would continue to be amortized in accordance with full cost accounting rules.

At June 30, 2003 and December 31, 2002, the Company had undeveloped
leaseholds of approximately $4.4 million and $4.6 million respectively, that would be classified on the consolidated balance sheet as intangible undeveloped leaseholds and no amounts that would be classified as intangible developed
leaseholds, if the Company applied the interpretations currently being discussed.

The Company will continue to classify its oil and gas mineral rights held under lease and other contractual
rights representing the right to extract such reserves as tangible oil and gas properties until further guidance is provided.

Stock-Based Compensation

Statements of Financial Accounting Standards Nos. 148 and No. 123 encourage, but do not require, companies to record the compensation cost for stock-based employee compensation plans at fair value.  At June 30, 2003, the
Company had two stock-based employee option plans and warrants issued to directors and employees.  The Company has chosen to continue to account for stock-based compensation using the intrinsic value method prescribed in Accounting Principles
Board Opinion No. 25, Accounting for Stock Issued to Employees, (APB 25) and has applied the disclosure provisions of SFAS 123 and 148.  Accordingly, compensation cost for fixed stock options and warrants is measured as
the excess, if any, of the quoted market price of the Companys stock at the date of the grant over the amount a director or employee must pay to acquire the stock.  Pro forma disclosures as if the Company had adopted the cost recognition
provisions of SFAS 123 are presented below.

|                                                                                            |  | Six months ended June 30 |           
|------------------------------------------------------------------------------------------- |  | ------------------------ | ----------
|                                                                                            |  |                          |           
|                                                                                            |  | 2003                     |           
|                                                                                            |  |                          |           
|Net loss as reported                                                                        |  | $                        | (4,341,000
|Add:                                                                                        |  |                          |           
|Total compensation cost included in reported net loss, net of tax                           |  |                          |          
|Deduct:                                                                                     |  |                          |           
|Total compensation cost determined under fair value based method for all awards, net of tax |  |                          | (73,000   
|                                                                                            |  |                          |           
|Pro forma net loss                                                                          |  | $                        | (4,414,000
|                                                                                            |  |                          |           
|Loss per share                                                                              |  |                          |           
|Basic and diluted - as reported                                                             |  | $                        | (.11      
|Basic and diluted - pro forma                                                               |  | $                        | (.11      

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Ceiling Test Write-Down

The Company accounts for its oil and gas properties using the full cost method.  Under
this method, the Company is required to record a permanent impairment provision if the net book value of its oil and gas properties less related deferred taxes exceeds a ceiling value equal to the present value of the future cash inflows from proved
reserves, discounted at 10% plus the cost of unproved properties not being amortized and the lower of cost or fair value of unproved properties being amortized, less the related tax effects.  The ceiling test is computed by country and at the
end of each quarter.  The oil and gas prices used in calculating future cash inflows in the United States are based upon the market price on the last day of the accounting period.  Oil and gas prices are generally volatile; and if the
market prices at a period end date have decreased, the Company may have to record an impairment.  A loss may also be generated by the transfer of significant early stage exploratory costs to the oil and gas property cost pool that is subject to
the ceiling test.  These losses typically occur when significant costs are transferred to the oil and gas property cost pool as a result of an unsuccessful project without commercially productive oil and gas production.  During the second
quarter of 2002, the Company recorded a ceiling test write-down of $2.2 million.  The write-down is the direct result of extended production testing and further drilling that caused the Company to significantly reduce the proved reserves
previously attributed to its Nine Mile properties.

Gas Imbalances

In natural gas production operations, joint owners sometimes sell more
or less than the production volumes to which they are entitled based on their revenue ownership interest.  The joint operating agreement includes gas balancing provisions to govern production allocations in this situation.  The Company
records a natural gas imbalance in other liabilities if any excess takes of natural gas exceed its remaining proved reserves for the property.  As of June 30, 2003, the Company had taken and sold more than its share of natural gas volumes
produced from the Comet Ridge project, and was overproduced by approximately 1,568,000 Mcf.  Based on the average price of $1.40 per Mcf received during the first six months of 2003 from these sales, this represents $2,195,000 in gas
revenues.  No liability has been recorded for the excess volumes taken as they do not exceed the Companys share of remaining proved reserves.  Under the terms of the gas balancing agreement, the Company may be required to reduce the
monthly volumes it sells by up to 50% of its entitled share of sales, to enable underproduced parties to sell more than their entitled share of the gas sales and cure the imbalance.  Any reduction in monthly volumes will negatively affect the
Companys revenues, and operating expenses will not decline proportionately.

Foreign Currency Translation

Effective April 1, 2003,
the Company changed the functional currency of its Australian subsidiary (TOGA) from the U.S. dollar to the Australian dollar.  In April 2003, the Company began borrowing Australian dollars under its new debt agreement with STEL
(Note 2).  That fact, combined with TOGAs assumption of operations of the Comet Ridge project and increased gas sales from the project, results in substantially all of TOGAs transactions being denominated in the Australian
dollar.  As the functional currency is the local currency, the current rate method is used to translate Australian dollar financial statements into U.S. dollars for TOGA.  All assets and liabilities are translated using current exchange
rates, while revenues and expenses are translated at rates in existence when the transactions occurred.  The translation adjustment that results from using varying rates in the translation process is reported as a component of other
comprehensive income and is accumulated and reported as a separate line item in stockholders equity in the Companys Consolidated Financial Statements.

As a result of the change in
functional currency effective April 1, 2003, the Company recorded an initial foreign currency translation adjustment of $249,000.  The cumulative foreign currency translation adjustment as of June 30, 2003 totaled $3,804,000.  As of June
30, 2003, TOGA owed the Company approximately $48 million which was denominated in U.S. dollars.  In accordance with SFAS No. 52, Foreign Currency Translation (SFAS 52), the Company recognized a

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foreign currency exchange gain of $3,113,000 related to the $24 million of intercompany debt payments discussed in Note 2.

Liquidity and Operations

The Company anticipates funding operations and domestic and Australian  non-discretionary exploratory capital expenditures for the
remainder of 2003 using (a) net gas revenues; (b) funds remaining (appproximately $10 million) under the $25 million credit facilities from Slough Trading Estates Limited (STEL), a UK company and wholly-owned subsidiary of Slough Estates
plc and  parent of Slough Estates USA Inc. (Slough), which owns 61.3% of the Companys outstanding common stock (See Note 2 to the Consolidated Financial Statements); and (c) $3 million of net proceeds from the sale of the
Stateline prospect (See Note 8 to the Consolidated Financial Statements).

In order to fund discretionary capital expenditures in 2003 in excess of these cash resources and to fund capital
expenditures beyond 2003, the Company contemplates that it will require alternative sources of capital.  Potential additional sources of funding are expected to include additional debt financings and asset sales.  The  Company is
currently in formal discussions with a group of banks interested in providing debt financing to TOGA.  The Company is seeking the financing to be (a) available in the fourth quarter of 2003, (b) secured by the Companys consolidated
interests in the Comet Ridge project in Queensland, Australia, and (c) partially guaranteed by Slough Estates plc, STELs UK parent.  If obtained, the Company anticipates that the financing would be used to repay the Companys
long-term debt with STEL, including the new $29 million long-term debt described in Note 2 to the Consolidated Financial Statements, and (to the extent available) fund Comet Ridge development in 2003, 2004 and early 2005.

On an ongoing basis, the Company seeks to sell interests in its exploration acreage inventory in the United States and retain carried working interests.  In the event of such sales, the Company generates cash to
reduce its investment in individual projects and fund exploration costs.  However, in the event that sufficient capital cannot be generated from property sales or other funding cannot be obtained, the Company will be required to curtail planned
expenditures and may have to sell additional acreage and/or relinquish acreage at prices that are not favorable to the Company.

NOTE 2 - RELATED PARTY TRANSACTIONS

In March 2003, the Company entered into two credit facility agreements with STEL allowing the Company  to borrow on an unsecured basis up to $25 million from STEL.  Interest is 13% per annum, payable
quarterly and the loans mature on April 2, 2012.  The Company may repay the loans in whole or in part without prepayment penalties. STEL may demand repayment prior to the maturity date provided that STEL gives 18-month notice.  The Company
may continue to borrow under the STEL credit facilities during the 18-month notice period.  Approximately two-thirds of the $25 million will be available to TOGA directly and in Australian dollars.  Borrowings by TOGA may be used for
exploration, development, and production costs of the Comet Ridge project as well as TOGAs general and administrative costs and interest expense. Other Company borrowings may  be used for general corporate purposes.

At June 30, 2003, the Company owed Slough and STEL $21,102,000.  The first obligation, a loan from Slough for a drilling rig, is evidenced by a note payable with a balance of $1,670,000 at June 30, 2003. 
Principal payments on the rig loan are due monthly from rents received from the drilling contractor during the month. However, there are no mandatory principal payments prior to the maturity date. The loan bears interest at a rate of 10% per annum
payable monthly and the note matures on October 31, 2004.  Under the second obligation, the $25 million credit facility with STEL, the Company owes $15.4 million ($9.4 million of which was denominated in Australian dollars).  The Company
has also borrowed $4 million from Slough which is due  on April 30, 2004, and is evidenced by a note payable and bears an interest rate of LIBOR plus 3.5% (4.62% as of June 30, 2003).  Additionally, the Company borrowed $4.7 million on a
short-term basis from Slough during the first quarter  of 2003 under the same terms as the $4 million Slough note payable.  In April 2003, the Company used $4.7 million of the $25 million credit facility entered into with STEL in March
2003 to retire this short-term debt.

The board of directors of the Company and TOGA have approved the borrowing of an additional $29 million from STEL by TOGA for the sole purpose of paying off the
$22 million long-term debt owed TCW and to substantially fund the $7.7 million repurchase of the 6% overriding royalty held by TCW on the Companys Comet Ridge properties.  TOGA intends to borrow those funds on August 15, 2003.  As a
result of TOGA retiring the TCW debt, the Company expects TOGAs intercompany debt with the Company to be reduced by approximately $24 million.  Interest on the $29 million note

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payable due STEL will be 13% per annum, payable quarterly and the loan will mature on February 2, 2005.  Terms of the agreement will be substantially the same as those in
the March 2003 $25 million credit facility agreement with STEL. As a result of retiring the TCW debt, the TCW deferred loan costs of $5.1 million will be expensed in full in the third quarter of 2003.

NOTE 3 - LONG-TERM DEBT - UNRELATED PARTY

The Company is a party to an amended and restated Credit Agreement with TCW with a principal balance of $22 million, which
was used for development of the Comet Ridge project.  As explained in Note 2 to the Consolidated Financial Statements, the Company intends to repay this loan on August 15, 2003.

When the TCW
loan is paid in full, the Company has the right to purchase the royalty interest from TCW for the sum of (a) the net present value of the royalty interests share of future net revenues (after certain gas delivery costs) from the then proved
reserves, discounted at 15.865% per annum plus (b) such additional amount, if any, to provide TCW a 15.865% internal rate of return without consideration of the value in (a).  The Company intends to exercise this right and purchase the royalty
for $7.7 million on August 15, 2003.

The amended Credit Agreement contains customary default provisions, including the failure to make required principal payments, under which TCW may require all
obligations to be immediately due and payable.  The amended Credit Agreement requires that TOGA maintain working capital of at least $500,000.  As of June 30, 2003, the Company had met all debt covenants under the Credit Agreement with
TCW.

The Company recorded deferred financing costs of approximately $6,800,000 in connection with the TCW credit agreement, which was the then present value (discounted at 15%) of the overriding
royalty conveyed to TCW. This cost reduced the book value of the Companys oil and gas properties in Australia and was amortized as interest expense over the life of the loan.  Deferred loan costs  also include approximately
$1,683,000 of other costs incurred to obtain the TCW financing, which were likewise amortized as interest expense over the life of the loan.  As described in Note 2 to the Consolidated Financial Statements, the remaining unamortized deferred
loan costs of $5.1 million will be expensed in full in the third quarter of 2003 if the TCW debt is repaid as planned.

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NOTE 4  LOSS  PER SHARE

The following table sets forth the computation of basic and diluted loss per
share (EPS) (in thousands except per share data):

|                                                                                                                                                              |  | Three months ended June 30 |        | Six months ended June 30 |  
|------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | -------------------------- | ------ | ------------------------ | -
|                                                                                                                                                              |  |                            |        |                          |  
|                                                                                                                                                              |  | 2003                       |        | 2002                     |  
|                                                                                                                                                              |  |                            |        |                          |  
|Numerator:                                                                                                                                                    |  |                            |        |                          |  
|Net loss                                                                                                                                                      |  | $                          | (1,626 | )                        | $
|Denominator:                                                                                                                                                  |  |                            |        |                          |  
|Weighted average shares outstanding                                                                                                                           |  |                            | 39,221 |                          |  
|Effect of dilutive securities:                                                                                                                                |  |                            |        |                          |  
|Assumed conversion of dilutive options and warrants                                                                                                           |  |                            |       |                          |  
|                                                                                                                                                              |  |                            |        |                          |  
|Weighted average shares and dilutive potential common shares                                                                                                  |  |                            | 39,221 |                          |  
|                                                                                                                                                              |  |                            |        |                          |  
|Basic and diluted loss per share                                                                                                                              |  | $                          | (.04   | )                        | $
|                                                                                                                                                              |  |                            |        |                          |  
|Number of shares of potentially dilutive common stock from the exercise of options and warrants not included in EPS because they would have been
antidilutive |  |                            | 132    |                          |  
|                                                                                                                                                              |  |                            |        |                          |  
|Total common stock options and warrants that could potentially dilute basic EPS in future periods                                                             |  |                            | 3,573  |                          |  
|                                                                                                                                                              |  |                            |        |                          |  

NOTE 5 - COMMITMENTS AND CONTINGENCIES

The
Company, TOGA and two unaffiliated working interest owners are plaintiffs in a lawsuit filed in 1998, styled Tipperary Corporation and Tipperary Oil & Gas (Australia) Pty Ltd v. Tri-Star Petroleum Company, James H. Butler, Sr., and James
H. Butler, Jr., Cause No. CV42,265, District Court of Midland County, Texas involving the Comet Ridge project.  The plaintiffs allege, among other matters, that Tri-Star and/or the individual defendants failed to operate the project in
a good and workmanlike manner and committed various other breaches of a joint operating contract, breached a previous mediation agreement, committed certain breaches of fiduciary and other duties owed to the plaintiffs, and committed fraud in
connection with the project.  Tri-Star answered the allegations, and filed a counterclaim alleging tortious interference with respect to the contracts, the authority to prospect covering the project and contractual relationships with vendors;
commercial disparagement; foreclosure of operators lien and alternatively forfeiture of undeveloped acreage; unjust enrichment and declaratory relief.  As of February 2001, the District Court enjoined Tri-Star from asserting any
forfeiture claims based upon events prior to that date.  In March 2002, the court entered its Writ of Temporary Injunction (the Injunction) to enforce the votes of a majority-in-interest of the parties under the joint operating
agreement to remove Tri-Star as operator and replace it with TOGA, which occurred on March 22, 2002.  Tri-Star appealed the Injunction to the Texas Eighth District Court of Appeals.  On January 31, 2003, the appellate court affirmed the
action of the District Court in issuing the Injunction.  Tri-Star filed a Petition for Review in the Supreme Court of Texas which was denied on July 3, 2003.  Any Motion for Reconsideration of the denial of Petition for Review must be
filed in the Supreme Court of Texas by August 18, 2003.  Unless the Texas Supreme Court reconsiders the July 3, 2003 order, takes the case for decision and overturns the decision of the Eighth Court of Appeals, TOGA will continue as operator of
the Comet Ridge Project at least through the conclusion of a trial on the merits, and thereafter if successful at trial.

In June 2002, the District Court ruled as unenforceable the arbitration
provisions of the existing mediation agreement between the parties and the obligation of the parties to arbitrate audit disputes.  The District Court refused to refer any issues between the parties to arbitration. On July 10, 2002, Tri-Star
filed an accelerated appeal of the order in the Texas

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Eighth District Court of Appeals.  On May 29, 2003, the appellate court affirmed the order of the District Court, and on July 2, 2003, denied Tri-Stars Motion for
Reconsideration.  Tri-Star may file a Petition for Review of this matter in the Texas Supreme Court, and the Supreme Court has discretion to either hear, or refuse to hear, the appeal.   Although pre-trial discovery is proceeding, the
pending appeal continues to delay the trial on the merits, and a new trial date will not be set before all appellate proceedings are resolved.

In January of 2003, the Company filed a Motion to
Compel Compliance with Amended Writ of Temporary Injunction in the Midland County District Court. The Company has asked the District Court to compel Tri-Star to assign title in the Comet Ridge petroleum titles to TOGA, in proportion to TOGAs
working interest, arguing that without such title TOGA, as operator, cannot control all aspects of the project as contemplated by the joint operating agreement and the Injunction.  That motion is set for hearing beginning August 13, 2003.

In 2002 TOGA, as operator of the Comet Ridge project, requested that Tri-Star repay to other working interest owners $1.3 million of unapplied prepaid drilling costs.  The Companys
share is $940,000 as of June 30, 2003, and the Company has recorded a fully reserved receivable, with no gain recognizable until the receivable is paid or payment is reasonably certain.  Tri-Star does not recognize the debt of $1.3 million to
the Company and other owners, largely because the Company and other plaintiffs in the aforementioned lawsuit had previously disputed $1.3 million of prior joint interest billings and paid $1.3 million into the registry of the District Court, rather
than to Tri-Star.

By not returning the $1.3 million of unused prepaid drilling costs, it is the Companys opinion that Tri-Star has effectively collected the $1.3 million of joint interest
billings still in dispute in the Court.  Therefore, the Company and other plaintiffs have filed a Motion to Withdraw, seeking return of the $1.3 million held in the Registry of the Court, and that Motion will also be heard beginning August 13,
2003.  If the funds are returned under that Motion, the Company will receive $1.3 million and record a $940,000 recovery of bad debt.

To the extent the Court eventually finds that all or a
portion of the disputed Tri-Star billings were inappropriate, Tri-Star would owe up to $1.2 million additional monies to the Company.  The additional sums, if the full $1.2 million is received, would be recorded as a $1 million recovery of
capital costs and a $200,000 recovery of operating expenses.  It is the Companys opinion that the May 29, 2003 Appellate Court affirmation of the lower courts decision strongly supports the Companys position that the billings
were inappropriate.

The Company may be entitled to additional damages based upon Tri-Stars billing practices and handling of the arbitration process if the June 21, 2002 ruling of the
District Court is upheld on final appeal.

NOTE 6 - OPERATIONS BY GEOGRAPHIC AREA

The Company has one operating and reporting segment -
oil and gas exploration, development and production - in the United States and Australia.  Information about the Companys operations by geographic area is shown below (in thousands):

|                                                           |  | Australia |        | United States |   | Total | 
|---------------------------------------------------------- |  | --------- | ------ | ------------- | - | ----- | 
|                                                           |  |           |        |               |   |       | 
|Operating revenue for the three months ended June 30, 2003 |  | $         | 1,705  |               | $ | 4     | 
|Operating revenue for the three months ended June 30, 2002 |  | $         | 1,043  |               | $ | 167   | 
|                                                           |  |           |        |               |   |       | 
|Operating revenue for the six months ended June 30, 2003   |  | $         | 3,043  |               | $ | 7     | 
|Operating revenue for the six months ended June 30, 2002   |  | $         | 1,920  |               | $ | 562   | 
|                                                           |  |           |        |               |   |       | 
|Property, plant and equipment, net, at June 30, 2003       |  | $         | 81,867 |               | $ | 8,599 | 
|Property, plant and equipment, net, at December 31, 2002   |  | $         | 66,881 |               | $ | 7,459 | 

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NOTE 7 PROPERTY, PLANT AND EQUIPMENT

A summary of property, plant and equipment follows:

|                                                          |  | June 30 2003 |        | December 31 2002 |  
|--------------------------------------------------------- |  | ------------ | ------ | ---------------- | -
|                                                          |  |              |        |                  |  
|Evaluated oil and gas properties:                         |  |              |        |                  |  
|Evaluated Australian properties                           |  | $            | 79,288 |                  | $
|Evaluated domestic properties                             |  |              | 40     |                  |  
|Unevaluated oil and gas properties:                       |  |              |        |                  |  
|Unevaluated Australian properties                         |  |              | 4,842  |                  |  
|Unevaluated domestic properties                           |  |              | 8,402  |                  |  
|                                                          |  |              |        |                  |  
|Oil and gas properties                                    |  |              | 92,572 |                  |  
|Other property and equipment                              |  |              | 4,350  |                  |  
|                                                          |  |              |        |                  |  
|                                                          |  |              | 96,922 |                  |  
|Less accumulated depreciation, depletion and amortization |  |              | (6,456 | )                |  
|                                                          |  |              |        |                  |  
|Property, plant and equipment, net                        |  | $            | 90,466 |                  | $
|                                                          |  |              |        |                  |  

NOTE 8 - SUBSEQUENT EVENTS

In July 2003, the Company sold to an unaffiliated third party, a 75% interest
in the Stateline prospect in western Nebraska for $3 million in cash.  The Company retained a 25% interest in the acreage.  Total gross acreage sold in the project is approximately 97,000 acres.  The purchaser will serve as operator
of the project.  In accordance with full cost accounting standards, the Company will record the proceeds as a reduction of its domestic full cost pool, with no gain being recognized unless nonrecognition significantly alters the relationship
between the pools costs and its proved reserves.

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Item 2.  Managements Discussion and Analysis

Information within this report contains forward-looking
statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are based on managements beliefs, assumptions, current expectations, estimates and projections about the oil and gas industry, the world economy and
about the Company itself.  Words such as may, will, expect, anticipate, estimate or continue, or comparable words are intended to identify such forward-looking statements.
In addition, all statements other than statements of historical facts that address activities that the Company expects or anticipates will or may occur in the future are forward-looking statements.  These statements are not guarantees of future
performance and involve certain risks, uncertainties and assumptions that are difficult to predict with regard to timing, extent, likelihood and degree of occurrence.  Therefore, actual results and outcomes may materially differ from what may
be expressed or forecasted in such forward-looking statements. Furthermore, the Company undertakes no obligation to update, amend or clarify forward-looking statements, whether as a result of new information, future events or otherwise. Readers are
encouraged to read the SEC filings of the Company, particularly its Form 10-KSB for the year ended December 31, 2002, for meaningful cautionary language disclosing why actual results may vary materially from those anticipated by
management.

Overview

Australia

In the first six months of 2003,
the Australian dollar strengthened in relation to the US dollar, increasing 19% from US$0.56 to US$0.67 and providing approximately US$14 million in added value to the Companys standardized measure of discounted future net cash
flows.

Effective April 1, 2003, the Company changed the functional currency of its Australian subsidiary (TOGA) from the U.S. dollar to the Australian dollar.  In
April 2003, the Company began borrowing Australian dollars under its new debt agreement with STEL (Note 2).  That fact, combined with TOGAs assumption of operations of the Comet Ridge project and increased gas sales from the project,
results in substantially all of TOGAs transactions being denominated in the Australian dollar.  As the functional currency is the local currency, the current rate method is used to translate Australian dollar financial statements into
U.S. dollars for TOGA.  All assets and liabilities are translated using current exchange rates, while revenues and expenses are translated at rates in existence when the transactions occurred.  The translation adjustment that results from
using varying rates in the translation process is reported as a component of other comprehensive income and is accumulated and reported as a separate line item in stockholders equity in the Companys Consolidated Financial
Statements.

As the Australian dollar is now the functional currency, the Companys U.S. dollar financial statements will be impacted if, and when, the Australian dollar strengthens in
relation to the U.S. dollar in the following ways:  (a) TOGAs U.S. dollar short-term debt becomes less expensive to repay, and the Company will record foreign currency gains, (b) TOGAs long-term assets acquired in prior years using
U.S. dollars when the Australian dollar was weaker increase in value, and the increased value is reflected on the balance sheet with the accumulated translation adjustment increasing, and (c) TOGAs Australian dollar denominated assets and
liabilities will not influence foreign exchange gains and losses rather, the accumulated translation adjustment will increase or decrease as necessary.  If TOGA repays the TCW debt as described in Note 2 to the Consolidated Financial
Statements, the majority of TOGAs debt will be denominated in Australian dollars.  Currently all TOGA revenues and the majority of operating and capital expenses are denominated in Australian dollars.

The Companys activities in Australia are conducted substantially through the Companys 90%-owned Australian subsidiary, Tipperary Oil & Gas (Australia) Pty Ltd (TOGA).  As of June 30, 2003, the
Company owned a total of 73% in undivided capital bearing interest in the Comet Ridge project in Queensland, Australia.  This project comprises approximately 1,058,000 acres in the Bowen Basin and includes five petroleum leases covering
approximately 278,000 acres, Authority to Prospect (ATP) 526 covering approximately 687,000 acres, and ATP 653 covering approximately 93,000 acres.

An ATP allows the holder to
undertake a range of exploration activities, including geophysical surveys, field mapping and exploratory drilling. Each ATP requires the expenditure of an amount of exploration costs as determined by Queenslands

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Department of Natural Resources and Mines (Queensland DNRM) and is subject to renewal every four years. Once a petroleum resource is identified, the holder of an
ATP may apply for a petroleum lease, which provides the lessee with the ability to conduct additional exploration, development and production activities.

During 2003, ATP 526 and 653 have
remaining expenditure requirements totaling approximately $6.2 million net to the Companys interest.  The Company expects to either meet these requirements by conducting seismic operations and exploratory drilling, or receive permission
from the DNRM to amend the requirements.  ATP 526 and 653 have initial terms expiring on October 31, 2004 and September 30, 2006, respectively.

The table below summarizes field development
progress on the Comet Ridge project.  The Company anticipates completing the installation of a second compression plant facility in September 2003.  Upon completion of the facility, the Company will be able to sell gas volumes from eight
new wells, increasing the total number of wells capable of sales to 44 from the 36 wells that were selling at June 30, 2003.  In addition, the Company will begin to reduce volumes or shut-in production from other selling wells in an effort to
significantly reduce flared gas volumes.  Upon completion of the second compression plant facility, the Company will have approximately 10 Mmcf per day of excess capacity for gas production and the necessary facilities to transport and sell
those volumes.  The Company has additional wells not yet equipped with production facilities or gathering lines that are capable of producing an additional 15 Mmcf per day of gas.  Additional sales are dependent upon gas purchasers making
requests to purchase more gas volumes under existing contracts and/or the Company entering into additional contracts to sell available gas volumes.

Comet Ridge Operations Review:

|                                    |  | June 30 2003 |    | March 31 2003 |  | December 31 2002 | 
|----------------------------------- |  | ------------ | -- | ------------- |  | ---------------- | 
|                                    |  |              |    |               |  |                  | 
|Well Status (Number of Gross Wells) |  |              |    |               |  |                  | 
|Selling                             |  |              | 36 |               |  | 34               | 
|Dewatering or Shut-in               |  |              | 28 |               |  | 26               | 
|                                    |  |              |    |               |  |                  | 
|Producing                           |  |              | 64 |               |  | 60               | 
|Being Completed                     |  |              | 13 |               |  | 11               | 
|Completion not Planned              |  |              | 2  |               |  | 3                | 
|Plugged and Abandoned               |  |              | 1  |               |  | 1                | 
|                                    |  |              |    |               |  |                  | 
|Drilled                             |  |              | 80 |               |  | 75               | 
|                                    |  |              |    |               |  |                  | 
|Gross Daily Volumes (Mmcf)          |  |              |    |               |  |                  | 
|Sold                                |  |              | 17 |               |  | 17               | 
|Flared                              |  |              | 10 |               |  | 7                | 
|Used for Compression Fuel           |  |              | 2  |               |  | 2                | 
|                                    |  |              |    |               |  |                  | 
|Produced                            |  |              | 29 |               |  | 26               | 
|                                    |  |              |    |               |  |                  | 

The Company plans to drill approximately 30 development wells on the Comet Ridge project during 2003, and
expects to fund its share of drilling costs with financing received under a $25 million borrowing facility entered into in March 2003 with Slough Trading Estates Limited, a United Kingdom company which is affiliated with the Companys majority
shareholder. See Note 2 to the Consolidated Financial Statements.

During the first and second quarters of 2003, the Company sold 100% of the gas for which it had sales contracts in Australia under
two contracts with ENERGEX Retail Pty Ltd (ENERGEX), an unaffiliated customer. The first contract has delivery requirements of up to approximately 5,500 Mcf of gas per day through December 2003. A second five-year contract, entered into
with ENERGEX effective June 1, 2000, has delivery requirements of up to approximately 15,000 Mcf of gas per day.  In December 2002, the Company entered into a gas sales agreement with Origin Energy Retail Limited (OERL), a
subsidiary of Origin Energy Limited, to supply approximately 9 Bcf per year, or around 25,000 Mcf of gas per day net to the Companys interests, for thirteen years beginning May 2007.

Effective June 30, 2003, the Company and Queensland Fertilizer Assets Limited (QFAL) were discussing the extension until September 30, 2003 of the Companys gas sales agreement with QFAL to supply 260 Bcf of
gas over a 20-year

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period beginning in late 2005 to a fertilizer plant QFAL is proposing to construct in southeastern Queensland.  The Company believes it has reasonable certainty, based
upon the gas market in Eastern Australia, that this production can be sold in the market, if not sold to QFAL.

In addition to the interest in the Comet Ridge project, TOGA holds a 100% interest in
ATPs 655 and 675 covering approximately 278,000 acres in total as of June 30, 2003.  ATPs 655 and 675 have initial terms expiring on October 31, 2003 and February 29, 2004, respectively.  TOGA has drilled and completed a total
of six exploratory wells on these ATPs,  three of which are being tested and evaluated, and three of which were plugged and abandoned.  TOGA has met all prior term expenditure requirements on retained acreage.  TOGA also holds a 25%
interest in ATP 554, which covers approximately 111,000 acres.

During the current term ending October 31, 2003, ATP 655 has remaining expenditure requirements totaling approximately $924,000. 
During the current term ending February 29, 2004, ATP 675 has no remaining expenditure requirements.  The Company will continue to evaluate ATPs 655 and 675 and will either meet the expenditure requirements or relinquish additional
acreage based upon evaluation of data.  On ATP 554 several conditions must be met by a third party before the Company can determine its commitment.

United States

The Company holds a 50% working interest in and serves as operator of the Lay Creek coalseam gas project located in Moffat County, Colorado. The project includes various leasehold interests covering over 82,000
gross acres. Koch Exploration Company (Koch), an unaffiliated third party, holds the remaining 50% working interest under the terms of an agreement to conduct exploratory drilling over this area jointly. Koch paid the Company
approximately $2 million for this interest at closing in May 2001 and agreed to pay the Company approximately $2 million for the Companys share of costs to drill and complete wells on the project acreage. The Company drilled and completed two
exploratory coalseam gas wells on this acreage during 2001 and completed a four-well pilot drilling program around one of the exploratory wells in early May 2002.  During the third and fourth quarters of 2002, the Company drilled four
additional exploratory coalseam gas wells offsetting the second exploratory well drilled in 2001 in the project.  The Company is currently evaluating the gas and water production from these two five-well pilot programs in order to determine
economic viability of the production.  The Company plans to drill additional pilot wells in 2003.

In February 2002, the Company sold a 60% interest in the Nine Mile Prospect, a conventional
oil and gas exploration prospect, which is also located in Moffat County, Colorado, to Elm Ridge Resources (Elm Ridge), an unaffiliated third party, for approximately $595,000.  Elm Ridge also agreed to pay one-half of the
Companys share of drilling costs to an agreed casing point on the first well for its 40% retained interest.  On September 17, 2002,  the Company announced the completion and initial testing of the Federal 34-1 in the prospect. 
The Company and Elm Ridge subsequently drilled the Federal 3-1 well in the fourth quarter of 2002 to further test the productive formation.  Elm Ridge served as operator of the project through March 25, 2003.  The Company became operator
of the Nine Mile prospect on March 26, 2003 after the resignation of the former operator.  During the second quarter of 2003, the Company completed and tested the Federal 3-1 well that was drilled in late 2002.  The Federal 3-1 well did
not produce gas in commercial quantities and the Company plans to plug and abandon the well.  Also during the second quarter of 2003, the Company drilled and completed the Federal 2-1 well.  The Federal 2-1 well also did not have
commercial quantities of gas and the Company plans to plug and abandon the well.  The Company elected to perform an extended production test on the Federal 34-1 well in the second quarter of 2003.  In July 2003, the Company received
disappointing results from the extended production test and believes the reservoir associated with the Federal 34-1 well is significantly smaller than initially estimated.  The Company has taken a ceiling test write-down as of June 30, 2003 of
$2.2 million under the full cost method of accounting.  The project comprises approximately 49,000 gross acres.  The Company plans to commence additional exploratory activities in the fourth quarter of 2003.

In November 2002, the Company sold to Kerr-McGee Rocky Mountain Corporation (Kerr-McGee), an unaffiliated third party, interests ranging from 75% to 80% in the Frenchman and Republican prospects in eastern Colorado
for $4,800,000 in cash.  The Company retained the remaining 25% to 20% interests in the acreage.  Total acreage in the project is approximately 280,000 gross acres.  The Company and Kerr-McGee simultaneously entered into a joint
operating agreement designating Kerr-McGee as operator.  As a result of the sale, the Company recorded a $1,400,000 gain in the fourth quarter of 2002.  In the second quarter of 2003, the Company drilled its first well on the Frenchman
prospect and

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completion operations are now underway.  The Company expects to drill at least five additional wells on the Frenchman and Republican prospects in the remainder of
2003.

In July 2003, the Company sold to an unaffiliated third party, a 75% interest in the Stateline prospect in western Nebraska for $3 million in cash.  The Company retained a 25% interest
in the acreage.  Total gross acreage sold in the project is approximately 97,000 acres.  The purchaser will serve as operator of the project.  In accordance with full cost accounting standards, the Company will record the proceeds as
a reduction of its domestic full cost pool, with no gain being recognized unless non-recognition significantly alters the relationship between the pools costs and its proved reserves.

Financial Condition, Liquidity and Capital Resources

The Company had unrestricted cash and cash equivalents of $1,946,000 as of June 30, 2003, compared to
$1,725,000 as of December 31, 2002.  During the second quarter of 2003, the Company received approximately $15 million in cash, drawing on the $25 million long-term, unsecured credit facilities described in Note 2 to the Consolidated Financial
Statements.  Working capital includes restricted cash of $152,000 as of June 30, 2003 and $546,000 as of December 31, 2002.  Restricted cash  consists of cash in collateral bank accounts that was maintained in connection with the TCW
financing, the use of which was restricted to disbursements made either to TCW or as otherwise approved by TCW.  The Company has funded operations and capital expenditures for the six months ended June 30, 2003, using primarily (a) $1.7 million
of cash on hand  at December 31, 2002, (b) a $4.7 million short-term loan from Slough in February and March 2003 that was repaid on April 2, 2003, and (c) $15 million in borrowings from STEL described previously.

The Company anticipates funding operations and domestic and Australian  non-discretionary exploratory capital expenditures for the remainder of 2003 using (a) net gas revenues; (b) funds remaining (approximately $10
million) under the $25 million credit facilities from Slough Trading Estates Limited (STEL), a UK company and wholly-owned subsidiary of Slough Estates plc and parent of Slough Estates USA Inc. (Slough), which owns 61.3% of
the Companys outstanding common stock ( See Note 2 to the Consolidated Financial Statements); and (c) $3 million of net proceeds from the sale of the Stateline prospect (See Note 8 to the Consolidated Financial Statements).

In order to fund discretionary capital expenditures in 2003 in excess of these cash resources and to fund capital expenditures beyond 2003, the Company contemplates that it will require alternative sources of
capital.  Potential additional sources of funding are expected to include additional debt financings and asset sales.  The  Company is currently in formal discussions with a group of banks interested in providing debt financing to
TOGA.  The Company is seeking the financing to be (a) available in the fourth quarter of 2003, (b) secured by the Companys consolidated interests in the Comet Ridge project in Queensland, Australia, and (c) partially guaranteed by Slough
Estates plc, STELs UK parent.  If obtained, the Company anticipates that the financing would be used to repay the Companys long-term debt with STEL, including the $29 million long-term debt the Company intends to borrow as described
in Note 2 to the Consolidated Financial Statements, and (to the extent available) fund Comet Ridge development in 2004 and early 2005.

On an ongoing basis, the Company seeks to sell its interests
in its prospective acreage in the United States and retain carried working interests.  In the event of such sales, the Company generates cash to reduce its investment in individual projects and fund exploration costs.  However, in the
event that sufficient capital cannot be generated from property sales or other funding cannot be obtained, the Company will be required to curtail planned expenditures and may have to sell additional acreage and/or relinquish acreage at prices that
are not favorable to the Company.

Net cash used by operating activities was $3,087,000 during the six months ended June 30, 2003 compared to $2,420,000 of cash used during the same period last
year.  The use of cash for operations in both periods resulted primarily from (a) interest expense on debt used to fund property acquisition, exploration and development and (b) the sale of most of the Companys U.S. oil and gas properties
after June 30, 2000. However, the loss in revenues from domestic properties has been partially offset by steadily increasing sales of natural gas in Australia.

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##### Table of Contents

The table below provides a detailed analysis of capital expenditures of $11.98 million during the six months ended June 30, 2003.

Capital Expenditures Activity (in thousands)

|Australia:                           |  |   |        | 
|------------------------------------ |  | - | ------ | 
|Comet Ridge drilling and  completion |  | $ | 4,719  | 
|Comet Ridge facilities and equipment |  |   | 3,432  | 
|Other                                |  |   | 234    | 
|Domestic:                            |  |   |        | 
|Leasehold acquisitions               |  |   | 1,477  | 
|Nine Mile drilling and completion    |  |   | 1,164  | 
|Lay Creek drilling and completion    |  |   | 487    | 
|Frenchman exploratory                |  |   | 144    | 
|Other                                |  |   | 325    | 
|                                     |  |   |        | 
|Total                                |  | $ | 11,982 | 
|                                     |  |   |        | 

In January 2001, Slough advanced the Company $2,500,000 for the purchase of a drilling rig which the
Company has leased to an unaffiliated drilling contractor in Australia.  This loan bears interest at a fixed rate of 10% per annum and matures on October 31, 2004. Payments are due monthly equal to all rents the Company receives from the
drilling contractor and for accrued interest on the balance of the loan.  However, there are no mandatory principal payments prior to the maturity.  During the first six months of 2003, the Company received $240,000 in rent which was used
for principal payments. As of June 30, 2003, the balance due on this loan was $1,670,000.  The drilling contractor has an option to buy the drilling rig from the Company prior to June 2006 for a cash payment equal to the loan balance when the
option is exercised.

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##### Table of Contents

Results of Operations - Comparison of the Three Months Ended June 30, 2003 and 2002

The Company incurred a
net loss of $1,626,000 for the three months ended June 30, 2003, compared to a net loss of $937,000 for the three months ended June 30, 2002.  The increased net loss for the three months ended June 30, 2003 is primarily due to $413,000 of
additional interest expense due to higher loan balances.  Other significant transactions included a $2.2 million write-down of oil and gas properties in 2003 and a $766,000 gain on the sale of assets in 2002 offset by a $3.1 million foreign
currency gain in 2003.  The table below provides a comparison of operations for the three months ended June 30, 2003 with those of the prior years quarter.

|                                                        |  | Three Months Ended June 30 |           | Increase (Decrease) |   | % Increase (% Decrease) | 
|------------------------------------------------------- |  | -------------------------- | --------- | ------------------- | - | ----------------------- | 
|                                                        |  |                            |           |                     |  
|                                                        |  | 2003                       |           | 2002                |   |                         | 
|                                                        |  |                            |           |                     |   |                         | 
|Worldwide operations:                                   |  |                            |           |                     |   |                         | 
|                                                        |  |                            |           |                     |   |                         | 
|Operating revenue                                       |  | $                          | 1,709,000 |                     | $ | 1,210,000               | 
|Other revenue                                           |  | $                          |          |                     | $ | 42,000                  | 
|Other expense                                           |  | $                          | (48,000   | )                   | $ | 1,000                   | 
|Gas volumes (Mcf)                                       |  |                            | 1,171,000 |                     |   | 880,000                 | 
|Oil volumes (Bbls)                                      |  |                            |          |                     |   | 4,000                   | 
|Average gas price per Mcf                               |  | $                          | 1.46      |                     | $ | 1.27                    | 
|Average oil price per Bbl                               |  |                            | N/A       |                     | $ | 23.93                   | 
|Operating expenses                                      |  | $                          | 1,113,000 |                     | $ | 714,000                 | 
|Average operating cost per Mcf equivalent (Mcfe) sold |  | $                          | 0.95      |                     | $ | 0.79                    | 
|General and administrative                              |  | $                          | 1,291,000 |                     | $ | 1,039,000               | 
|Depreciation, depletion and amortization (DD&A)       |  | $                          | 398,000   |                     | $ | 412,000                 | 
|Interest expense                                        |  | $                          | 1,175,000 |                     | $ | 762,000                 | 
|                                                        |  |                            |           |                     |   |                         | 
|Australia operations:                                   |  |                            |           |                     |   |                         | 
|                                                        |  |                            |           |                     |   |                         | 
|Operating revenue                                       |  | $                          | 1,705,000 |                     | $ | 1,043,000               | 
|Gas volumes (Mcf)                                       |  |                            | 1,170,000 |                     |   | 855,000                 | 
|Average gas price per Mcf                               |  | $                          | 1.46      |                     | $ | 1.22                    | 
|Operating expenses                                      |  | $                          | 888,000   |                     | $ | 572,000                 | 
|Average operating cost per Mcf sold                     |  | $                          | 0.76      |                     | $ | 0.67                    | 
|Oil and Gas property DD&A                               |  | $                          | 372,000   |                     | $ | 289,000                 | 
|Other DD&A                                              |  | $                          | 14,000    |                     | $ | 64,000                  | 
|Oil and Gas DD&A rate per Mcf volumes sold              |  | $                          | 0.32      |                     | $ | 0.34                    | 
|                                                        |  |                            |           |                     |   |                         | 
|Domestic operations:                                    |  |                            |           |                     |   |                         | 
|                                                        |  |                            |           |                     |   |                         | 
|Operating revenue                                       |  | $                          | 4,000     |                     | $ | 167,000                 | 
|Gas volumes (Mcf)                                       |  |                            | 1,000     |                     |   | 25,000                  | 
|Oil volumes (Bbls)                                      |  |                            |          |                     |   | 4,000                   | 
|Average gas price per Mcf                               |  | $                          | 4.00      |                     | $ | 3.03                    | 
|Average oil price per Bbl                               |  |                            | N/A       |                     | $ | 23.93                   | 
|Operating expenses                                      |  | $                          | 225,000   |                     | $ | 141,000                 | 
|Average operating cost per Mcfe sold                    |  | $                          | 225.00    |                     | $ | 2.96                    | 
|Oil and Gas property DD&A                               |  | $                          |          |                     | $ | 46,000                  | 
|Other DD&A                                              |  | $                          | 12,000    |                     | $ | 12,000                  | 
|Oil and Gas DD&A rate per Mcfe volumes sold             |  |                            |          |                     | $ | 0.94                    | 

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##### Table of Contents

Revenues and Sales Volumes

Gas volumes sold in Australia increased 37% due to increased gas sales from existing
wells, new wells drilled and an increase in gas deliveries.  Gas revenues in Australia increased by 63% due to the increase in sales volumes, an increase in the average sales price received and to changes in exchange rates.  The
Companys gas sales contracts in Australia are long-term fixed price contracts with yearly adjustments for inflation.  The 19% increase in average gas sales price in Australia is due primarily to the inflation adjustments and due to a 15%
approximate increase in the value of the Australian dollar in relation to the U.S. dollar.

In natural gas production operations, joint owners sometimes sell more or less than the production volumes
to which they are entitled based on their revenue ownership interest.  The joint operating agreement includes gas balancing provisions to govern production allocations in this situation.  The Company records a natural gas imbalance in
other liabilities if any excess takes of natural gas exceed its remaining proved reserves for the property.  As of June 30, 2003, the Company had taken and sold more than its share of natural gas volumes produced from the Comet Ridge project,
and was overproduced by approximately 1,568,000 Mcf.  Based on the average price of $1.40 per Mcf received during the first six months of 2003 from these sales, this represents $2,195,000 in gas revenues.  No liability has been recorded
for the excess volumes taken as they do not exceed the Companys share of remaining proved reserves.  Under the terms of the gas balancing agreement, the Company may be required to reduce the monthly volumes it sells by up to 50% of its
entitled share of sales, to enable underproduced parties to sell more than their entitled share of the gas sales and cure the imbalance.  Any reduction in monthly volumes will negatively affect the Companys revenues, and operating
expenses will not decline proportionately.

During the second quarter of 2003, the Company had minimal domestic revenue.  Domestic revenues and volumes in 2002 related to the West Buna field
which the Company sold in the second quarter of 2002.

Costs and Expenses

Operating expenses in Australia increased 55% due to an
increase in the number of producing wells, increased costs associated with delivering increasing gas volumes and a 15% approximate decrease in the value of the U.S. dollar in relation to the Australian dollar.  Operating expenses also increased
due to the Companys increase in ownership in the Comet Ridge project in mid-2002.  Australian oil and gas property DD&A expense increased 29% due to increasing sales volumes, offset by improvements in the DD&A rate as a result of
a decline in future development costs per well.

Domestic operating expenses in the second quarter of 2003 are largely attributable to the Lay Creek coal bed methane project where the initial ten
wells are in the early dewatering phase.  Without these Lay Creek operating expenses, the average domestic operating cost per Mcf sold would be reduced substantially to $1.99 per Mcf.  Operating expenses in the second quarter of 2002
include expenses from the West Buna field.  Domestic DD&A expenses decreased in 2003 due to the aforementioned sale of the Companys West Buna field.

General and administrative
(G&A) expenses for the second quarter of 2003 increased 24% when compared to the three months ended June 30, 2002.  For the second quarter of 2003, increased G&A costs can be attributed to taking over operations at Comet
Ridge and ongoing litigation with Tri-Star. See Note 5 to the Consolidated Financial Statements.

Other Income (Expense)

Interest expense
increased to $1,175,000 from $762,000, due primarily to increased loan balances in the second quarter of 2003 when compared to the same period in 2002.  As of June 30, 2003, TOGA owed the Company approximately $48 million which was denominated
in U.S. dollars.  It is the intention of the Company that TOGA will repay approximately 50% of this balance during 2003, while the remainder is expected to be converted to equity.  In accordance with SFAS No. 52, Foreign Currency
Translation (SFAS 52), the Company recognized a foreign currency exchange gain of $3,113,000 related to the debt to be repaid.

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##### Table of Contents

Results of Operations - Comparison of the Six Months Ended June 30, 2003 and 2002

The Company incurred a net
loss of $4,341,000 for the six months ended June 30, 2003, compared to a net loss of $2,520,000 for the six months ended June 30, 2002.  The greater net loss for the six months ended June 30, 2003 is primarily due to $1,086,000 of additional
interest expense and a $741,000 increase in operating expenses offset by a $568,000 increase in revenues. Interest expense increased by approximately $420,000 as a result of expensing loan issuance and break-up costs for a $25 million loan scheduled
to close in the first quarter of 2003 that was replaced by the STEL credit facilities, which the Company believes have more favorable terms.  The remaining interest expense increase was due to higher loan balances in 2003. Operating expense
increases were caused primarily by increases in the production and sale of gas in Australia. Other significant transactions included a $2.2 million write-down of oil and gas properties in 2003 and a $766,000 gain on the sale of assets in 2002,
offset by a $3.1 million foreign currency gain in 2003. The table below provides a comparison of operations for the six months ended June 30, 2003 with those of the six months ended June 30, 2002.

|                                                        |  | Six Months Ended June 30 |           | Increase (Decrease) |   | % Increase (% Decrease) |  
|------------------------------------------------------- |  | ------------------------ | --------- | ------------------- | - | ----------------------- | -
|                                                        |  |                          |           |                     |  
|                                                        |  | 2003                     |           | 2002                |   |                         |  
|                                                        |  |                          |           |                     |   |                         |  
|Worldwide operations:                                   |  |                          |           |                     |   |                         |  
|                                                        |  |                          |           |                     |   |                         |  
|Operating revenue                                       |  | $                        | 3,050,000 |                     | $ | 2,482,000               |  
|Other revenue                                           |  | $                        |          |                     | $ | 122,000                 |  
|Other expense                                           |  | $                        | 4,000     |                     | $ | (15,000                 | )
|Gas volumes (Mcf)                                       |  |                          | 2,183,000 |                     |   | 1,700,000               |  
|Oil volumes (Bbls)                                      |  |                          |          |                     |   | 13,900                  |  
|Average gas price per Mcf                               |  | $                        | 1.40      |                     | $ | 1.29                    |  
|Average oil price per Bbl                               |  |                          | N/A       |                     | $ | 21.14                   |  
|Operating expenses                                      |  | $                        | 2,064,000 |                     | $ | 1,323,000               |  
|Average operating cost per Mcf equivalent (Mcfe) sold |  | $                        | 0.95      |                     | $ | 0.74                    |  
|General and administrative                              |  | $                        | 2,812,000 |                     | $ | 2,586,000               |  
|Depreciation, depletion and amortization (DD&A)       |  | $                        | 706,000   |                     | $ | 835,000                 |  
|Interest expense                                        |  | $                        | 2,480,000 |                     | $ | 1,394,000               |  
|                                                        |  |                          |           |                     |   |                         |  
|Australia operations:                                   |  |                          |           |                     |   |                         |  
|                                                        |  |                          |           |                     |   |                         |  
|Operating revenue                                       |  | $                        | 3,043,000 |                     | $ | 1,920,000               |  
|Gas volumes (Mcf)                                       |  |                          | 2,181,000 |                     |   | 1,614,000               |  
|Average gas price per Mcf                               |  | $                        | 1.40      |                     | $ | 1.19                    |  
|Operating expenses                                      |  | $                        | 1,682,000 |                     | $ | 1,051,000               |  
|Average operating cost per Mcf sold                     |  | $                        | 0.77      |                     | $ | 0.65                    |  
|Oil and Gas property DD&A                               |  | $                        | 654,000   |                     | $ | 537,000                 |  
|Other DD&A                                              |  | $                        | 28,000    |                     | $ | 110,000                 |  
|Oil and Gas DD&A rate per Mcf volumes sold              |  | $                        | 0.29      |                     | $ | 0.34                    |  
|                                                        |  |                          |           |                     |   |                         |  
|Domestic operations:                                    |  |                          |           |                     |   |                         |  
|                                                        |  |                          |           |                     |   |                         |  
|Operating revenue                                       |  | $                        | 7,000     |                     | $ | 562,000                 |  
|Gas volumes (Mcf)                                       |  |                          | 2,000     |                     |   | 86,000                  |  
|Oil volumes (Bbls)                                      |  |                          |          |                     |   | 13,900                  |  
|Average gas price per Mcf                               |  | $                        | 3.95      |                     | $ | 3.14                    |  
|Average oil price per Bbl                               |  |                          | N/A       |                     | $ | 21.14                   |  
|Operating expenses                                      |  | $                        | 382,000   |                     | $ | 272,000                 |  
|Average operating cost per Mcfe sold                    |  | $                        | 191.00    |                     | $ | 1.61                    |  
|Oil and Gas property DD&A                               |  | $                        |          |                     | $ | 162,000                 |  
|Other DD&A                                              |  | $                        | 25,000    |                     | $ | 25,000                  |  
|Oil and Gas DD&A rate per Mcfe volumes sold             |  |                          |          |                     | $ | 0.96                    |  

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Revenues and Sales Volumes

Gas volumes sold in Australia increased 35% due to increased gas sales from existing
wells, new wells drilled and an increase in gas deliveries, despite unusual pipeline maintenance in February 2003 that reduced net volumes for that month by approximately 85,000 Mcf (9%) compared to January and March 2003 sales levels.  Gas
revenues in Australia increased by 58% due to the increase in sales volumes, an increase in the average sales price received and to changes in exchange rates.  The Companys gas sales contracts in Australia are long-term fixed price
contracts with yearly adjustments for inflation.  The 18% increase in average gas sales price in Australia is due primarily to the inflation adjustments and due to a  16% approximate increase in the value of the Australian dollar in
relation to the U.S. dollar.

During the first six months of 2003, the Company had minimal domestic revenue.  Domestic revenues and volumes in 2002 relate to the West Buna field which the
Company sold in the second quarter of 2002.

Costs and Expenses

Operating expenses in Australia increased 60% due to an increase in the
number of producing wells, increased costs associated with delivering increasing gas volumes and a 16% approximate decrease in the value of the U.S. dollar in relation to the Australian dollar.  Operating expenses also increased due to the
Companys increase in ownership in the Comet Ridge project in mid-2002.  Australian oil and gas property DD&A expense increased 22% due to increasing sales volumes, offset by improvement in the DD&A rate as a result of a decline in
future development costs per well.

Domestic operating expenses in the first six months of 2003 are largely attributable to the Lay Creek coal bed methane project where the initial ten wells are in
the early dewatering phase.  Without these Lay Creek operating expenses, the average domestic operating cost per Mcf sold would be reduced substantially to $2.05 per Mcf.  Operating expenses in the first six months of 2002 include expenses
from the West Buna field.  Domestic DD&A expenses decreased due to the aforementioned sale of the Companys West Buna field.

General and administrative (G&A) expenses
for the first six months of 2003 increased 9% when compared to the six months ended June 30, 2002.  For the first six months of 2003, increased G&A costs associated with taking over operations at Comet Ridge were offset by a significant
decline in legal costs as compared to the first six months of 2002.

Other Income (Expense)

Interest expense increased to $2,480,000 from
$1,394,000, due to the one-time expensing of approximately $420,000 associated with loan issuance and break-up costs for a $25 million loan scheduled to close in the first quarter of 2003 that was replaced by the STEL credit facilities, which the
Company believes have more favorable terms to the Company.  Interest expense also increased due to increased loan balances in the first six months of 2003 when compared to the same period in 2002.  As of June 30, 2003, TOGA owed the
Company $48 million which was denominated in U.S. dollars.  It is the intention of the Company that TOGA will repay approximately 50% of this balance during 2003, while the remainder is expected to be converted to equity.  In accordance
with SFAS No. 52, Foreign Currency Translation (SFAS 52), the Company recognized a foreign currency exchange gain of $3,113,000 related to the debt to be repaid.

Item 4. Controls and Procedures

As of the end of the period covered by this report, we evaluated, under the supervision and
with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures over financial reporting pursuant to Rule 13a-15 and
15d-15 of the Securities Exchange Act of 1934. Based upon that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures over financial reporting are adequate and effective in
timely alerting them to material information required to be included in this quarterly report on Form 10-Q.

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##### Table of Contents

Disclosure controls and procedures, no matter how well designed and implemented, can provide only reasonable assurance of achieving an entitys disclosure objectives. The
likelihood of achieving such objectives is affected by limitations inherent in disclosure controls and procedures. These limitations include the fact that human judgment in decision-making can be faulty and that breakdowns in internal control can
occur because of human failures such as simple errors or mistakes or because of intentional circumvention of the established process.

During the period covered by this report, there have been no
significant changes in our internal controls over financial reporting or in other factors, which could significantly affect internal controls over financial reporting, including any corrective actions with regard to significant deficiencies or
material weaknesses.

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##### Table of Contents

PART II - OTHER INFORMATION

|Item 1. | Legal Proceedings                                                         
|------- | --------------------------------------------------------------------------
|        |                                                                           
|        | See Note 5 to the Consolidated Financial Statements under Part I - Item 1.
|        |                                                                           
|Item 6. | Exhibits and Reports on Form 8-K                                          
|        |                                                                           
|        | (a)                                                                       
|        |                                                                           
|        |                                                                           
|        |                                                                           
|        |                                                                           
|        |                                                                           
|        |                                                                           
|        |                                                                           
|        |                                                                           
|        |                                                                           
|        |                                                                           
|        |                                                                           
|        |                                                                           
|        |                                                                           
|        |                                                                           
|        |                                                                           
|        | (b)                                                                       
|        |                                                                           
|        |                                                                           
|        |                                                                           

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##### Table of Contents

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this
report to be signed on its behalf by the undersigned thereunto duly authorized.

|      |                 |     | TIPPERARY CORPORATION                                                                       
|----- | --------------- | --- | --------------------------------------------------------------------------------------------
|      |                 |     |                                                                                             
|      |                 |     | Registrant                                                                                  
|      |                 |     |                                                                                             
|      |                 |     |                                                                                             
|Date: | August 14, 2003 | By: | /s/ DAVID L. BRADSHAW                                                                       
|      |                 |     |                                                                                             
|      |                 |     | David L. Bradshaw, President, Chief Executive Officer and Chairman of the Board of Directors
|      |                 |     |                                                                                             
|      |                 |     |                                                                                             
|Date: | August 14, 2003 | By: | /s/ JOSEPH B. FEITEN                                                                        
|      |                 |     |                                                                                             
|      |                 |     | Joseph B. Feiten, Chief Financial Officer and Principal Accounting Officer                  

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EXHIBIT INDEX

|11.   | Computation of per share earnings, filed herewith as Note 4 to the Consolidated Financial Statements.                                                                                                  
|----- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|      |                                                                                                                                                                                                        
|10.97 | Amendment to Gas Sales Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ACN 077 536 871) as Seller and Queensland Fertilizer Assets Limited (ACN 011 062 294) as Buyer, dated
March 31, 2003.
|      |                                                                                                                                                                                                        
|31.1  | Certification of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002.                                                                                                          
|      |                                                                                                                                                                                                        
|31.2  | Certification of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002.                                                                                                          
|      |                                                                                                                                                                                                        
|32.1  | Certification of Chief Executive Officer of Tipperary Corporation  Pursuant to 18 U.S.C. §1350                                                                                                         
|      |                                                                                                                                                                                                        
|32.2  | Certification of Chief Financial Officer of Tipperary Corporation  Pursuant to 18 U.S.C. §1350.                                                                                                        

24